Bitumen—colloquially known as “tar” due to its similar appearance, odor, and color—is a thick, sticky form of crude oil. It is so heavy and viscous that it will not flow unless either heated or diluted with lighter hydrocarbons. Bituminous sands—known as oil sands or tar sands—contain naturally occurring mixtures of sand, clay, water, and bitumen and are found in extremely large quantities in Canada and Venezuela.
Conventional crude oil is normally extracted from the ground by drilling oil wells into a reservoir, and allowing oil to flow into the wells under natural reservoir pressures. Artificial lift techniques, such as water flooding and gas injection, are usually required to maintain production as reservoir pressure drops toward the end of a field's life, but initial production proceeds under normal reservoir pressures and temperatures.
Oil sands are very different however. Because extra-heavy oil and bitumen flow very slowly (if at all) toward producing wells under normal reservoir conditions, oil sands must be extracted by strip mining or made to flow into wells by techniques designed to reduce the viscosity of the heavy oil. Such methods are called “enhanced oil recovery” (EOR) methods.
There are several EOR methods used to produce heavy oils that use steam as a source of heat to mobilize the heavy oil. In Cyclic Steam Stimulation (CSS) or the “huff-and-puff” method, the well is put through cycles of steam injection, soak, and oil production. First, steam is injected into a well at a temperature of 300-340° C. for a period of weeks to months. Then, the well is allowed to sit for days to weeks to allow heat to soak into the formation, and, later, the hot oil is pumped out of the well for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. The process is repeated until no longer cost effective. The CSS method recovery factor is around 20 to 25, but the cost to inject steam is high.
Steam assisted gravity drainage (SAGD) was developed in the 1980s and fortuitously coincided with improvements in directional drilling technology that made it quick and inexpensive to do by the mid 1990s. In SAGD, (at least) two horizontal wells are drilled in the oil sands, one at the bottom of the formation and another about 5 meters above it. Steam is injected into the upper well where the heat melts the heavy oil, which allows it to flow via gravity into the lower well, where it can be pumped to the surface. SAGD can be more cost effective than CSS in some formations, and allows very high oil production rates, and recovers up to 60% of the oil in place.
While being a breakthrough technology, the SAGD method is very costly in terms of water usage. The 1995 per-capita usage of water in the United States was estimated to be about 350 gal/day/person. Further, the American Petroleum Institute (API) estimates that 71% of produced water is being used for EOR methods, 21% is being injected for disposal, and 3% going to percolation and evaporation ponds, while only 5% is applied to beneficial uses such as for livestock, irrigation, etc. In fact, water is the largest waste stream produced by the oil & gas industry as a whole. Clearly, less water intensive methods would be of benefit to society as a whole, freeing up water usage for agrarian and humanitarian uses. Further, the water itself can damage the reservoir, since many of the oil sands contain clay that can swell on contact with water, thus reducing their permeability. Also, many reservoirs sites only have limited local water. Thus, there are many reasons for developing non-water based enhanced oil recovery techniques.
Some enhanced oil recovery (EOR) methodologies use solvents, instead of steam, to separate bitumen from sand. Solvent use can be beneficial if it does not approach the energy needed to produce steam. Also, as opposed to water that must be impounded and/or treated before release, solvent can be easily removed from the sands and re-used.
Vapor Extraction Process (VAPEX) is an in situ technology, similar to SAGD. Instead of steam, hydrocarbon solvents are injected into an upper well to dilute bitumen and enable the diluted bitumen to flow into a lower well. It has the advantage of much better energy efficiency over steam injection, and it allows some partial upgrading of bitumen to oil right in the formation.
The above methods are not mutually exclusive of course. It is becoming common for wells to be put through one CSS injection-soak-production cycle to condition the formation prior to going to SAGD production, and companies are experimenting with combining VAPEX with SAGD to improve recovery rates and lower energy costs.
In situ combustion (ISC) of heavy oil can also provide the heat to mobilize the heavy oil and can provide some in situ upgrading at the same time. This process is also known as “fire flooding.” Either dry air or air mixed with water is injected into the reservoir, and ideally, the fire propagates uniformly from the air injection well to the producing well, moving oil and combustion gases ahead of the burning front, and leaving coke behind the mobilized oil to provide the fuel for the combustion. See FIG. 1 for an exemplary ISC process.
Except in a few rare situations, in situ combustion has not been successfully applied. The fire front can be difficult to control, and may propagate in a haphazard manner resulting in premature breakthrough to a producing well. There is also a danger of a ruptured well with hot gases escaping to the surface. Temperatures in the thin combustion zone may reach several hundred degrees centigrade, so that the formation and completion hardware can be severely stressed.
Further, the produced fluid may contain an oil-water emulsion that is difficult to break. As with output from many heavy oil projects, it may also contain heavy-metal compounds that are difficult to remove in the refinery. In situ combustion eliminates the need for natural gas to generate steam, but significant energy is still required to compress and pump air into the formation.
Toe to Heel Air Injection (THAI) is variation of the in situ combustion method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the “toe” of the horizontal well toward the “heel”, which burns the heavier oil components and upgrades some of the heavy bitumen into lighter oil right in the formation. Although fireflood projects have not worked out well because of difficulty in controlling the flame front and a propensity to set the producing wells on fire, some believe the THAI method will eventually be more controllable, and in situ combustion techniques have the advantage of not requiring energy to create steam. Advocates of this method of extraction state that it uses less freshwater, produces 50% less greenhouse gases, and has a smaller footprint than other production techniques. An exemplary THAI method is shown in FIG. 2.
“CAPRI” is the variant of the THAI process that adds an annular sheath of solid catalyst surrounding the horizontal producer well. Thermally cracked oil produced by THAI passes through the layer of catalyst en-route to the horizontal producer well. Laboratory tests indicate that the combination of THAI and CAPRI can achieve significant upgrading. However, it is not clear that CAPRI can upgrade heavy oil to the point where it can be transported by pipeline without diluent. Thus, although a very promising technology, there is room for improvement.
Combustion Overhead Gravity Drainage (COGD) is another variant in situ combustion method that employs a number of vertical air injection wells above a horizontal production well located at the base of the bitumen pay zone. An initial Steam Cycle similar to CSS is used to prepare the bitumen for ignition and mobility. Following that cycle, air is injected into the vertical wells, igniting the upper bitumen and mobilizing (through heating) the lower bitumen to flow into the production well. It is expected that COGD will result in water savings of 80% compared to SAGD.
Finally, some companies are now experimenting with using electromagnetic (EM) energy to mobilize oil. Electrical heating tools and applications can be divided into two categories based on the frequency of the electrical current used. First, in low frequency mode (less than 60 Hz), currents are used for resistive heating. In this mode it is assumed that resistance heating dominates the process and other factors are negligible. Here the depth of penetration is high but the intensity low.
The second mode is a high frequency mode, wherein the currents are used in microwave (MW) or radio frequency (RF) range. The use of high frequencies for downhole dielectric heating has significant potential applications to heavy oil recovery. EM heating does not require a heat transporting fluid such as steam or a hot fluid injection process, which avoids the complications associated with generating and transporting a heated fluid, and allows it to be applied in wells with low incipient injectivity. EM heating can apply to situations where generating and injecting steam may be environmentally unacceptable (i.e., through permafrost), no wastewater disposal is required, and conventional oil field and electrical equipment can be used, which makes this technique very attractive for offshore heavy-oil recovery, though it has not yet been applied there. Furthermore, a single well can be used to introduce energy to the formation through a power source as well as to recover produced fluids. Production may occur during or immediately after EM heating if the formation pressure is large enough.
Inductive heating is a related technology that is sometimes distinguished from RF heating, and may use different electrode geometry, but fundamentally is based on the same principles.
Although promising, the value of RF or MW heating of reservoirs has yet to be fully realized, perhaps due to the lack of adequate modeling and difficulties in antenna design and placement, and difficulties with the durability of equipment. However, several companies are investigating this methodology and seeking ways of practical implementation.
One inherent problem with electrode systems is that they require either a new well with a completion designed especially for the system or a very extensive and often impractical re-working of an existing well.
Another problem is that oil reservoirs are not homogeneous and are often formed of layers of sediment of different physical and electrical characteristics. This leads to uneven heating wherein the least productive layers are heated the most, and surface temperatures near the ends of the electrodes can reach uncontrollably high levels causing their failure.
Electrode systems, whose test results have been reported, require the use of single phase, alternating current. Alternating current is used rather than direct current in order to maintain electrolytic corrosion in the well to an acceptable level. Electrode systems that utilize either a power cable or an insulated tubing string to deliver power to the electrodes can be operated at AC frequencies below normal power frequencies. This is done to minimize overheating that can occur in the power delivery system due to the induced currents that are generated in the ferromagnetic steel of the well casing and well accessories. Despite operating at quite low frequencies, damaging overheating can still result.
Electrode systems are fundamentally limited in the combined length of the electrodes being used, and, therefore, the thickness of exposed reservoir face that can be heated. The reason for this is that the efficiency of the electrode system is determined by the ratio of the electrical impedance of the electrodes divided by the electrical impedance of the entire system. The impedance of the electrodes is inversely proportional to their length and a function of the resistivity of the reservoir formation in contact with the electrodes.
The resistivities of oil bearing formations vary greatly depending primarily on their porosity and their saturation with oil, water, and gas. Also, the resistivity of the formation declines as its temperature increases; therefore, the impedance of the electrodes and the efficiency of the system go down as the formation face is heated. As a result of all these factors, the maximum thickness of sand face that can be efficiently heated with these systems is about fifteen meters.
One particularly intractable problem with electrode systems is that electrical tracking seems to inevitably occur across the surface of insulators exposed to the produced fluids from the wells. These fluids often are composed of two liquid phases, oil and salt water. At the electrical potential differences across insulators used in these systems, sparking occurs at the oil/water interface laying down a progressively larger track of carbon residue. Eventually a conductive path is formed, and sudden high currents can interrupt operations by blowing fuses and tripping breakers. If operations continue, production casing failures can occur, requiring abandonment or expensive recompletion of the well.
All of these problems have limited the usefulness of EM heating of reservoirs, which suggests that EM heating might benefit in a more limited application, where other methodologies also contribute to heat and drive mechanisms.
Thus, what is needed in the art is a method of improving the cost effectiveness of recovering heavy oils, even in heterogeneous reservoirs that are vertically compartmentalized.